It is the very paralysis created by these contradictory forces that leads to the possibility that the recent breakneck speed of shale-resource development will continue; no one can decide whether it is good or bad, so the market carries on. And it is the same policy stagnation that leads to de facto reliance on decision making by quasi-independent regulators, on whom the direction of domestic U.S. energy and environmental policies increasingly depends.

Perhaps best exemplifying this emergence of a new set of energy-policy drivers is what is happening in the utility sector of the United States. The U.S. Congress has been deadlocked on the issue of carbon policy; it appears there is no winning coalition across party lines that can either enact a carbon cap-and-trade system or a carbon tax. Attention therefore is on what might happen through regulation rather than legislation. Here, major regulatory events that are on the immediate horizon appear likely to reinforce the economics associated with the new competitiveness of natural gas. They will give a major boost to natural-gas use in electricity generation—at the expense of coal. The EPA’s Clean Air Interstate Rule, which aimed to reduce air pollution (in the form of sulfur dioxide and nitrogen oxide) from coal-fired power plants, is about to be replaced by an even-more-onerous framework—the Clean Air Transport Rule. It will likely have even-harsher emission limits on coal-fired generating units. Another related regulatory ruling is tied to the court-mandated need to replace the Clean Air Mercury Rule (which sought to require coal-fired utilities to reduce emissions of mercury) with a new maximum achievable control technology (MACT) rule aiming to reduce mercury emissions from industrial boilers, process heaters and solid-waste incinerators by more than 50 percent.

The EPA has until March of next year to draft the new MACT, which is scheduled to be implemented on a fast track for finalizing by November 2011. The MACT rule is designed to establish a ceiling on hazardous air pollutants by limiting emissions to levels that are now attained by the best performing 12 percent of all operating units. There is a good chance that sulfur-dioxide-control equipment—coal scrubbers—will prove to be the most effective available control technology. But about one-third of the 340 gigawatts (GW) of existing coal capacity in the United States lacks these scrubbers with no plans to install them. The costs are high—if 50 percent of those plants currently without the technology became compliant, the cost would be about $40 billion; if those plants that are partially controlled also decide to upgrade their scrubbers, the price tag could rise to $120–140 billion.

As a result of the costs confronting utilities in meeting new EPA standards, the likely course will be to retire oil-coal plants, replacing them mostly with gas-burning units. Thus far, U.S. utilities have announced plans to shut down some 20 GW of coal generation between now and 2020. Given the age and inefficiency of much of this industry, more likely than not 40–50 GW of retirements will occur between now and then, opening up demand for more natural-gas-burning units. If only 50 percent of the plants lacking controls are retired and replaced by gas-generating units, the demand for natural gas would grow by more than 10 percent in the United States, making the commodity the only available bridge to any future that needs to depend on renewables and nuclear energy.

On the other hand, the EPA is also undertaking studies to review the implications of shale gas in terms of those toxic fluids that are released in the process of fractionation to unleash gas and oil, as well as in terms of the adequacy of aquifers to support the water-intensive fracturing techniques. The current study is due to be completed by the end of 2012. In the meantime, the industry will maximize its shale finds in private leases where federal jurisdictions are—at least for the time being—less important than leases on federal lands. And though any eventual EPA decision will probably result in prolonged litigation between the extraction companies and the federal government—and between environmental groups and the federal government—for now the major pressures on further growth in shale-gas and oil extraction come from the marketplace itself.

THE UNITED States has been the main source of global gasoline-demand growth since 1990. But America has become less needy and less greedy with a concomitant ability to turn oil into gasoline with ease. Oil just isn’t what it used to be.

From 1990 until the middle of this decade, U.S. petroleum-product needs went up by 4 million barrels per day. Coupled with the decline in U.S. production, total American imports grew by around 6 million b/d. The increase in U.S. imports during this period was just shy of total Chinese demand. If the American economy was the most critical factor in tightening world oil markets then, it is now on a path of leadership in the opposite direction. That’s because the combination of new Corporate Average Fuel Economy (CAFE) standards and a rising renewable-fuel mandate should reduce gasoline demand from its peak of about 9.2 million b/d in 2007 to 7.8 million b/d in 2020. That’s a very large drop indeed.

The Obama administration looks prepared to help push U.S. needs down even further. The White House directed the Department of Transportation and the EPA to investigate 3–6 percent per annum increases in CAFE standards in the period 2017–2025, which already require 2016 vehicles to have a fuel efficiency of 35.5 miles per gallon, a 40 percent increase over the 2009 vehicle standard of 25 MPG.

With gasoline comprising 57 percent of total U.S. oil needs, and with the U.S. refining system having been built to capitalize on its manufacture, the drop in American gasoline demand is already having a significant impact on the market. The decline in U.S. demand has resulted in a reduction in gasoline prices versus heating oil. And with U.S. refiners trying to maximize production of more valuable diesel and heating oil, they are producing far more gasoline than is needed. As a result, the United States started to export finished motor gasoline last year for the first time since the mid-1950s. This has enabled refiners along the Gulf of Mexico coast to take advantage of a growing gasoline appetite in South America, and the radically increased difficulties of Venezuelan refining operations in recent years, to become suppliers of transportation fuels to Latin American markets.

The refining industry as a whole is under duress, largely because declining or stabilizing demand in Japan and Korea are turning those refiners into exporters as well; and this is all going on at the same time that Chinese and Indian producers, supported by government subsidies, have developed surplus supplies. Gasoline is, in effect, becoming a waste product in the United States and around the world.

THE REMARKABLE increases in natural-gas production in the United States were—up until Macondo—being mirrored in an equally remarkable growth in oil production in the deep water, where, just before the BP blowout, output had jumped from zero to 1.65 million barrels per day over the past five years, representing 35 percent of oil from deep water globally. All this meant relatively low energy prices for consumers.

Deepwater resources have several critical features—they are robust and they exist in many areas of the world where development problems have not been related to restricted governmental access by OPEC countries but rather to a lack of costly equipment to explore, delineate and develop resources. All of the 5-million-barrels-per-day growth in the last seven years has been in non-OPEC countries like the United States and Brazil. A new find will soon be developed in West Africa off the coast of Ghana. Robust natural-gas reserves have been found in the deep waters offshore India and Israel. Other such exploration is taking place along all three African coastal areas, offshore Australia, China, Indonesia, and in the Arctic waters of North America and Europe.

Before the blowout, production from the deep water was set to double between 2010 and 2018, with the United States likely to see its 35 percent share of global production maintained. Putting it in perspective, the United States consumes a total of some 20 million barrels per day of oil (including gasoline, jet fuel, home-heating oil and so on), and is producing about 7.2 million b/d of crude and other liquids. By the end of this decade, through a combination of U.S. shale-related oil production, offshore deepwater oil and reduced gasoline consumption, the gap between domestic production and imports was likely to be closed by more than 4 million b/d—about the same amount as total Iranian oil production and more than the total domestic production of China. While full oil independence might always be out of reach, major steps were under way to significantly reduce U.S. import dependence and vulnerability.

By and large, before Macondo, the decline in energy insecurity was being accomplished in an environmentally acceptable way. And, to the degree that there had been environmental issues posed, deepwater and shale production were providing a critical bridge to a lower-carbon future. But with the deepwater moratoria in place and new rigorous safety measures being implemented, it appears that at the end of the day, the United States will be losing 18–24 months of momentum in developing these resources. Instead of new development and new discoveries, production is inevitably declining in the interim. As a result, by 2017–18, under the best of circumstances, the United States will likely produce 300,000–500,000 b/d less per year than otherwise would have been the case. That level of lost production potentially looks to be the difference between moderate and much-higher prices around the world 4–6 years from now.